Dual attenuation peaks revealing mesoscopic and microscopic fluid flow in partially oil-saturated Fontainebleau sandstones

SUMMARY We conducted stress–strain oscillation experiments on dry and partially oil-saturated Fontainebleau sandstone samples over the 1–2000 Hz band at different confining pressures to investigate the wave-induced fluid flow (WIFF) at mesoscopic and microscopic scales and their interaction. Three tested rock samples have similar porosity between 6 and 7 per cent and were partially saturated to different degrees with different oils. The measurement results exhibit a single or two attenuation peaks that are affected by the saturation degree, oil viscosity and confining pressure. One peak, exhibited by all samples, shifts to lower frequencies with increasing pressure, and is mainly attributed to grain contact- or microcrack-related squirt flow based on modelling of its characteristics and comparison with other experiment results for sandstones. The other peak is present at smaller frequencies and shifts to higher frequencies as the confining pressure increases, showing an opposite pressure dependence. This contrast is interpreted as the result of fluid flow patterns at different scales. We developed a dual-scale fluid flow model by incorporating the squirt flow effect into the patchy saturation model, which accounts for the interaction of WIFFs at microscopic and mesoscopic scales. This model provides a reasonable interpretation of the measurement results. Our broad-frequency-band measurements give physical evidence of WIFFs co-existing at two different scales, and combining with modelling results, it suggests that the WIFF mechanisms, related to pore microstructure and fluid distribution, interplay with each other and jointly control seismic attenuation and dispersion at reservoir conditions. These observations and modelling results are useful for quantitative seismic interpretation and reservoir characterization, specifically they have potential applications in time-lapse seismic analysis, fluid prediction and reservoir monitoring.

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Time‐lapse (4-D) seismic monitoring of primary production of turbidite reservoirs at South Timbalier Block 295, offshore Louisiana, Gulf of Mexico

Geophysics ◽

10.1190/1.1444731 ◽

2000 ◽

Vol 65 (2) ◽

pp. 351-367 ◽

Cited By ~ 23

Author(s):

Tucker Burkhart ◽

Andrew R. Hoover ◽

Peter B. Flemings

Keyword(s):

Reservoir Characterization ◽

Water Saturation ◽

Seismic Analysis ◽

Time Lapse ◽

Hydrocarbon Production ◽

Seismic Surveys ◽

Seismic Amplitude ◽

Fluid Properties ◽

Multiple Reservoir ◽

Gas Drive

Two seismic surveys acquired over South Timbalier Block 295 field (offshore Louisiana) record significant differences in amplitude that are correlated to hydrocarbon production at multiple reservoir levels. The K8 sand, a solution‐gas‐drive reservoir, shows increases in seismic amplitude associated with gas exsolution. The K40 sand, a water‐drive reservoir, shows decreases in seismic amplitude associated with increases in water saturation. A methodology is presented to optimize the correlation between two seismic surveys after they have been individually processed (poststack) This methodology includes rebinning, crosscorrelation, band‐pass filtering, and cross‐equalization. A statistical approach is developed to characterize the correlation between the seismic surveys. This statistical analysis is used to discriminate seismic amplitude differences that record change in rock and fluid properties from those that could be the result of miscorrelation of the seismic data. Time‐lapse seismic analysis provides an important new approach to imaging hydrocarbon production; it may be used to improve reservoir characterization and guide production decisions.

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Exploring Reservoir within Hugin Formation in Theta Vest Structure using 4-D Seismic and Machine Learning Approach

IOP Conference Series Earth and Environmental Science ◽

10.1088/1755-1315/873/1/012042 ◽

2021 ◽

Vol 873 (1) ◽

pp. 012042

Author(s):

Lilik T. Hardanto ◽

Mirzam Abdurrachman ◽

Dwiharso Nugroho

Keyword(s):

Machine Learning ◽

Fluid Flow ◽

Seismic Analysis ◽

Time Lapse ◽

Seismic Inversion ◽

Seismic Survey ◽

Inversion Method ◽

Oil Distribution ◽

Flow Processes ◽

The Right

Abstract This paper aims to identify the oil distribution using 4-D seismic below a complex 3-D surface in Hugin Formation using machine learning and geobody detection. The exploration well 15/9-19-SR, drilled to the Theta Vest structure, was based on the interpretation of reprocessed ST8215R 3-D seismic survey data from 1991 in the Sleipner area, encountered oil in the Jurassic Hugin Formation. The drills stem test showed outstanding production capacities through time, with low water cut and low GOR. 4-D seismic has all the traditional benefits of 3-D seismic. A significant additional potential benefit is that fluid-flow processes can be directly imaged. The 4-D seismic analysis was conducted in 2012 to repeat the 3-D seismic surveys and analyze images in time-lapse mode to monitor time-varying fluid-flow processes during reservoir production. A comprehensive study of the structure and the discovery has been performed and is reported. The DNN method to predict facies far away from existing production wells by using facies log well to supervise seismic inversion created by the Seismic Color Inversion method. It can detect some oil pockets distribution and risk the well planning and the right candidate for new proposed wells.

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Time lapse seismic for reservoir characterization

10.29118/ipa.555.05.g.011 ◽

2018 ◽

Author(s):

R. Walia

Keyword(s):

Reservoir Characterization ◽

Time Lapse

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Near-surface real-time seismic imaging using parsimonious interferometry

Scientific Reports ◽

10.1038/s41598-021-86531-5 ◽

2021 ◽

Vol 11 (1) ◽

Author(s):

Sherif M. Hanafy ◽

Hussein Hoteit ◽

Jing Li ◽

Gerard T. Schuster

Keyword(s):

Fluid Flow ◽

Real Time ◽

Temporal Resolution ◽

Seismic Imaging ◽

Time Lapse ◽

Rock Properties ◽

Recording Time ◽

Near Surface ◽

Arrival Times ◽

Order Of Magnitude

AbstractResults are presented for real-time seismic imaging of subsurface fluid flow by parsimonious refraction and surface-wave interferometry. Each subsurface velocity image inverted from time-lapse seismic data only requires several minutes of recording time, which is less than the time-scale of the fluid-induced changes in the rock properties. In this sense this is real-time imaging. The images are P-velocity tomograms inverted from the first-arrival times and the S-velocity tomograms inverted from dispersion curves. Compared to conventional seismic imaging, parsimonious interferometry reduces the recording time and increases the temporal resolution of time-lapse seismic images by more than an order-of-magnitude. In our seismic experiment, we recorded 90 sparse data sets over 4.5 h while injecting 12-tons of water into a sand dune. Results show that the percolation of water is mostly along layered boundaries down to a depth of a few meters, which is consistent with our 3D computational fluid flow simulations and laboratory experiments. The significance of parsimonious interferometry is that it provides more than an order-of-magnitude increase of temporal resolution in time-lapse seismic imaging. We believe that real-time seismic imaging will have important applications for non-destructive characterization in environmental, biomedical, and subsurface imaging.

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Ensemble Machine Learning Assisted Reservoir Characterization Using Field Production Data–An Offshore Field Case Study

Energies ◽

10.3390/en14041052 ◽

2021 ◽

Vol 14 (4) ◽

pp. 1052

Author(s):

Baozhong Wang ◽

Jyotsna Sharma ◽

Jianhua Chen ◽

Patricia Persaud

Keyword(s):

Machine Learning ◽

Random Forest ◽

Reservoir Characterization ◽

Time Lapse ◽

Production Data ◽

Oil Saturation ◽

Ensemble Machine Learning ◽

Input Parameters ◽

Saturation Profiles ◽

Field Production

Estimation of fluid saturation is an important step in dynamic reservoir characterization. Machine learning techniques have been increasingly used in recent years for reservoir saturation prediction workflows. However, most of these studies require input parameters derived from cores, petrophysical logs, or seismic data, which may not always be readily available. Additionally, very few studies incorporate the production data, which is an important reflection of the dynamic reservoir properties and also typically the most frequently and reliably measured quantity throughout the life of a field. In this research, the random forest ensemble machine learning algorithm is implemented that uses the field-wide production and injection data (both measured at the surface) as the only input parameters to predict the time-lapse oil saturation profiles at well locations. The algorithm is optimized using feature selection based on feature importance score and Pearson correlation coefficient, in combination with geophysical domain-knowledge. The workflow is demonstrated using the actual field data from a structurally complex, heterogeneous, and heavily faulted offshore reservoir. The random forest model captures the trends from three and a half years of historical field production, injection, and simulated saturation data to predict future time-lapse oil saturation profiles at four deviated well locations with over 90% R-square, less than 6% Root Mean Square Error, and less than 7% Mean Absolute Percentage Error, in each case.

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Experiments and mechanistic modeling of viscosity effect on a multistage ESP performance under viscous fluid flow

Proceedings of the Institution of Mechanical Engineers Part A Journal of Power and Energy ◽

10.1177/09576509211014974 ◽

2021 ◽

pp. 095765092110149

Author(s):

Yi Shi ◽

Jianjun Zhu ◽

Haoyu Wang ◽

Haiwen Zhu ◽

Jiecheng Zhang ◽

...

Keyword(s):

Fluid Flow ◽

Viscous Fluid ◽

Prediction Error ◽

Flow Direction ◽

Fluid Viscosity ◽

Oil Viscosity ◽

Viscous Fluid Flow ◽

Viscosity Effect ◽

High Production Rate ◽

Pump Head

Assembled in series with multistage, Electrical Submersible Pumps (ESP) are widely used in offshore petroleum production due to the high production rate and efficiency. The hydraulic performance of ESPs is subjected to the fluid viscosity. High oil viscosity leads to the degradation of ESP boosting pressure compared to the catalog curves under water flow. In this paper, the influence of fluid viscosity on the performance of a 14-stage radial-type ESP under varying operational conditions, e.g. rotational speeds 1800–3500 r/min, viscosities 25–520 cP, was investigated. Numerical simulations were conducted on the same ESP model using a commercial Computational Fluid Dynamics (CFD) software. The simulated average pump head is comparable to the corresponding experimental data under different viscosities and rotational speeds with less than ±20% prediction error. A mechanistic model accounting for the viscosity effect on ESP boosting pressure is proposed based on the Euler head in a centrifugal pump. A conceptual best-match flowrate QBM is introduced, at which the impeller outlet flow direction matches the designed flow direction. The recirculation losses caused by the mismatch of velocity triangles and other head losses resulted from the flow direction change, friction loss and leakage flow etc., are included in the model. The comparison of model predicted pump head versus experimental measurements under viscous fluid flow conditions demonstrates good agreement. The overall prediction error is less than ±10%.

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Analysis of Fracture Roughness Control on Permeability Using SfM and Fluid Flow Simulations: Implications for Carbonate Reservoir Characterization

Geofluids ◽

10.1155/2019/4132386 ◽

2019 ◽

Vol 2019 ◽

pp. 1-19 ◽

Cited By ~ 9

Author(s):

Miller Zambrano ◽

Alan D. Pitts ◽

Ali Salama ◽

Tiziano Volatili ◽

Maurizio Giorgioni ◽

...

Keyword(s):

Fluid Flow ◽

Reservoir Characterization ◽

Flow Simulation ◽

Carbonate Reservoir ◽

Single Fracture ◽

Parallel Plates ◽

Surface Mapping ◽

Navier Stokes Equation ◽

Hydraulic Aperture ◽

Fracture Modeling

Fluid flow through a single fracture is traditionally described by the cubic law, which is derived from the Navier-Stokes equation for the flow of an incompressible fluid between two smooth-parallel plates. Thus, the permeability of a single fracture depends only on the so-called hydraulic aperture which differs from the mechanical aperture (separation between the two fracture wall surfaces). This difference is mainly related to the roughness of the fracture walls, which has been evaluated in previous works by including a friction factor in the permeability equation or directly deriving the hydraulic aperture. However, these methodologies may lack adequate precision to provide valid results. This work presents a complete protocol for fracture surface mapping, roughness evaluation, fracture modeling, fluid flow simulation, and permeability estimation of individual fracture (open or sheared joint/pressure solution seam). The methodology includes laboratory-based high-resolution structure from motion (SfM) photogrammetry of fracture surfaces, power spectral density (PSD) surface evaluation, synthetic fracture modeling, and fluid flow simulation using the Lattice-Boltzmann method. This work evaluates the respective controls on permeability exerted by the fracture displacement (perpendicular and parallel to the fracture walls), surface roughness, and surface pair mismatch. The results may contribute to defining a more accurate equation of hydraulic aperture and permeability of single fractures, which represents a pillar for the modeling and upscaling of the hydraulic properties of a geofluid reservoir.

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Capillary Equilibrium in Porous Materials

Society of Petroleum Engineers Journal ◽

10.2118/1011-pa ◽

1965 ◽

Vol 5 (01) ◽

pp. 15-24 ◽

Cited By ~ 61

Author(s):

Norman R. Morrow ◽

Colin C. Harris

Keyword(s):

Mass Transfer ◽

Fluid Flow ◽

Porous Materials ◽

Capillary Pressure ◽

Chemical Engineering ◽

Fluid Distribution ◽

Bulk Fluid ◽

Fluid Saturation ◽

Capillary Pressure Curves ◽

The Relationship

Abstract The experimental points which describe capillary pressure curves are determined at apparent equilibria which are observed after hydrodynamic flow has ceased. For most systems, the time required to obtain equalization of pressure throughout the discontinuous part of a phase is prohibitive. To permit experimental points to be described as equilibria, a model of capillary behavior is proposed where mass transfer is restricted to bulk fluid flow. Model capillary pressure curves follow if the path described by such points is independent of the rate at which the saturation was changed to attain a capillary pressure point. A modified suction potential technique is used to study cyclic relationships between capillary pressure and moisture content for a porous mass. The time taken to complete an experiment was greatly reduced by using small samples. Introduction Capillary retention of liquid by porous materials has been investigated in the fields of hydrology, soil science, oil reservoir engineering, chemical engineering, soil mechanics, textiles, paper making and building materials. In studies of the immiscible displacement of one fluid by another within a porous bed, drainage columns and suction potential techniques have been used to obtain relationships between pressure deficiency and saturation (Fig. 1). Except where there is no hysteresis of contact angle and the solid is of simple geometry, such as a tube of uniform cross section, there is hysteresis in the relationship between capillary pressure and saturation. The relationship which has received most attention is displacement of fluid from an initially saturated bed (Fig. 1, Curve Ro), the final condition being an irreducible minimum fluid saturation Swr. Imbibition (Fig. 1, Curve A), further desaturation (Fig. 1, Curve R), and intermediate scanning curves have been studied to a lesser but increasing extent. This paper first considers the nature of the experimental points tracing the capillary pressure curves with respect to the modes and rates of mass transfer which are operative during the course of measurement. There are clear indications that the experimental points which describe these curves are obtained at apparent equilibria which are observed when viscous fluid flow has ceased; and any further changes in the fluid distribution are the result of much slower mass transfer processes, such as diffusion. Unless stated otherwise, this discussion applies to a stable packing of equal, smooth, hydrophilic spheres supported by a suction plate with water as the wetting phase and air as the nonwetting phase. SPEJ P. 15ˆ

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